Subterranean deposits of natural resources such as gas, water, and crude oil are commonly recovered by drilling wellbores to tap subterranean formations or zones containing such deposits. Various wellbore servicing fluids are employed in drilling and preparing the wellbore and adjacent subterranean formations for the recovery of material therefrom. For example, a drilling fluid is usually circulated through the wellbore as it is being drilled. Generally, the drilling fluid may be used to cool and lubricate the drill bit, to remove drill cuttings, to condition the hole, to control wellbore pressures. Once a productive zone is encountered, the drilling fluid is commonly replaced by a Drill-In fluid, which has a role similar to that of an ordinary drilling mud, but may comprise a brine in order to minimize damage to the producing rock. Completion fluids may be used during the steps of completing the wellbore, and workover fluids may be used to perform remedial work in the wellbore.
Fluids suitable for use in a wellbore generally possess sufficient density to overcome the reservoir pressure and prevent unwanted fluid entry into the wellbore. Brines are commonly used for these purposes because their densities can be readily controlled by adjusting their compositions. In addition, such fluids may contain suspended solids for the purpose of controlling fluid loss into the rock adjacent to the wellbore.
One challenge to the use of brines in wellbore servicing is the generally low viscosity of the fluids. Higher viscosity brine-containing fluids would generally be useful for a number of reasons. For example, such fluids may find utility in controlling fluid loss as the rate at which fluid can enter the porous matrix of the reservoir rock as filtrate, during fluid loss, is proportional to the fluid viscosity. Further, such fluids may find additional utility if they are able to transport drill solids, solids trapped in the wellbore, or solid additives which again would be dependent upon the fluid viscosity. Polymers comprising hydroxyethyl cellulose (HEC) or xanthan gum have been used for thickening wellbore servicing fluids as they can dissolve in brines and produce shear thinning viscosity, as well as provide solids suspension capability and fluid loss control However, these polymers (i.e., HEC, xanthan gum) loose their thickening capacity at relatively low temperatures, thereby limiting their usefulness at temperatures exceeding about 240° F. for HEC, and 280° F. for the xanthan gum. In addition, these polymers may crosslink with multivalent cations in the brine at elevated temperatures, forming gels or precipitates. The loss of solubility of a thickener (e.g., HEC, xanthan gum) in the brine can cause formation or sand pack damage, thereby restricting the flow of hydrocarbons from the well. Thus a need exists for improved wellbore servicing fluids comprising brines and methods of using same.